Chemical scales that result from the deposition of solid salts from supersaturated solutions frequently lead to lost production or abandonment of production wells. Deposits can plug the wellbore, tubing string, downhole safety valves and other valves, and casing perforations. Subsurface pumps can stick and the operation of surface lines and equipment can be restricted.
Deposition can be initiated by a variety of factors, including pressure, pH, and temperature changes, turbulence, surface characteristics, or mixing of incompatible fluids. Incompatible fluids are frequently encountered during waterflooding operations. A common factor that causes scale is pressure reduction encountered by fluids as they enter the wellbore during production. The partial pressure of CO.sub.2 in a CO.sub.2 saturated brine decreases. Precipitation of CaCO.sub.3 results.
A variety of scales, both organic and inorganic, cause production problems. Common inorganic scales are calcium and magnesium carbonate, calcium, magnesium, barium, and strontium sulfate, and iron sulfides. The calcium salts are the most common. Barium scales ar especially difficult to prevent and remove.
Scales can either be removed or inhibited. Walls can also be re-perforated in order to circumvent the plugged area. Most plugging is at the perforation, where pressure changes are first seen. The well can also be fractured in order to bypass previously scaled areas. Both re-perforation and fracturing are expensive and only temporary remedies since scale will rapidly re-form.
Well clean-out can be mechanical or chemical, both of which are expensive. They both involved well shut-in during the cleaning operation. Scales are dissolved by acid treatments, base treatments, two stage treatments (bases followed by acids), and chelants such as EDTA (ethylendiaminetetraacetic acid). Chemicals can be converters or dissolvers. Converters, both inorganic and organic, form solid reaction products. Inorganic converters are usually preceded by an acidizing stage. Organic converters usually form dispersions or pumpable sludges, formed when the scales slough off from the surfaces. Better scale penetration is generally seen due to this sloughing. An acidizing stage generally follows the organic converter treatment. "Solvents," such as chelants, are more expensive but generally more effective.
Scales can be kept from forming by dilution. Fresh brine or a solubility-increasing brine can be injected into the formation to dilute the connate fluid past the solubility limit of the scalant. This procedure is also expensive.
The most efficient way of dealing with scale is to inhibit its formation. Chemicals can be sequestrants or work as threshold inhibitors. Sequestrants form combination pairs with a species normally involved in precipitation, such as calcium ions. The interaction with the sequestrant is on molar basis and therefore requires a large amount of chemical. While effective, this procedure could be cost limiting.
A much more cost effective chemical treatment is to use a threshold chemical, that is, one that inhibits at a concentration well below equimolar amounts. Threshold chemicals can be effective at concentrations as low as 1/1000th the concentration of the scaling mineral. Precipitation is a complicated process involving supersaturation, nucleation, and crystal growth. An inhibitor can function by one or more mechanisms. It can interfere with the nucleation process or rate. It can interfere with the can be altered. It can also prevent adhesion of crystals to one another or to metal walls. In order to be effective, the scale inhibitor must be present during the nucleation stage of crystal growth.
The most common classes of inhibitor chemicals are inorganic phosphates, organophosphorous compounds and organic polymers. The common phosphates are sodium tripolyphosphate and hexametaphosphate. Organophosphorous compounds are phosphonic acid and phosphate ester salts. The organic polymers used are generally low molecular weight acrylic acid salts or modified polyacrylamides and copolymers thereof. Phosphonates and polymers are more thermally stable than polyphosphates or phosphate esters. Phosphates hydrolyze at high temperatures forming orthophosphates, the metal salts of which may be more insoluble than the scales that they are intended to inhibit.
The phosphates have low brine solubilities and are therefore frequently injected as solids. They can be injected into the wellbore by bypass feeders, baskets, filter packs and bottom-ho1e well packs. They can also be placed into the formation through fractures along with the fracturing fluids. The chemical then dissolves slowly, resulting in a steady, low concentration of inhibitor.
The phosphonates and polymers are more water soluble and are therefore used as solutions. Either the wellbore or the formation can be treated. Both batch and continuous methods are used for treating the wellbore. It can also be added as a component of a fracturing fluid. These treatments are not optimum since chemical does not contact the point of initial scale formation--for formation face or casing perforations. However, the tubing string and surface equipment will be treated.
A more efficient and less costly procedure is a "squeeze" treatment, in which the chemical is injected into the formation. Production is halted while chemical is injected at a pressure below frac pressure. The chemical optically penetrates the formation to a distance 1-6 feet radially from the wellbore. Inhibitor will then be released into the wellbore as production is resumed. Ideally, the concentration of inhibitor is constant and low (at a concentration slightly above that required for total inhibition--generally 2-4 ppm). The lifetime of a squeeze depends on the flow rate, oil/water ratio and many other factors but can last for 6 months and even up to 2 years.
Squeeze treatments are generally used for production wells. The chemicals could also be used at injection wells to prevent scaling of the injection brines with reservoir brines (if the brines are incompatible). Plugging can occur at the injection well or can occur as the injection fluids contact the formation brines in the reservoir. The injection well would generally not be squeezed then brine withdrawn from the well. The chemical would travel with the injection brine to the producer, also resulting in inhibition of possible scale there. Injection brines themselves have generally reached maximum precipitation, since they have been at equilibrium for some time. Precipitation occurs when injection brine contacts formation brine in these cases. Frequently, the wells are still only treated at the producer, even when injection brines are being used. However, the chemical should be useful for injection wells also.
The chemical can be physically adsorbed or precipitated. Scale inhibitors are ionic (anionic) in nature. Therefore, the adsorption/desorption is believed to be controlled by electrostatic interactions between the inhibitor and formation minerals. Physically adsorbed chemical is generally retained for a shorter time than a precipitated inhibitor. Another possible mechanism of inhibitor retention is phase trapping. Inhibitor will be present in the brine in unswept areas. This inhibitor will then generally be produced back erratically within a few pore volumes of resumption of flow.
A proppant containing a physically adsorbed inhibitor can be injected into a fracture. The chemical will be released from the proppant as production returns. A similar method involves injection of microparticles of an ion exchange resin into the formation followed by inhibitor injection. The resin holds, then slowly releases, the chemical.
Inhibitors precipitated in the formation by multivalent ions have shown the longest squeeze lives. The concentration of inhibitor produced is controlled by the solubility of the inhibitor salt at a particular flow-rate. The chemical is precipitated with multivalent ions, generally calcium. Precipitation with other ions, such as iron or chromium, has been proposed.
The inhibitor can become exposed to the ions in several ways: First, multivalent ions that naturally occur in the reservoir brine can contact inhibitor solution during injection. Upon setting in the reservoir before production is resumed, multivalents can be ion-exchanged from the reservoir minerals. Secondly, an acidic inhibitor solution can be injected. As the acidic solution contacts calcium carbonate and reacts, calcium will be released and the pH will rise. Precipitation will result. Many sandstone reservoirs contain some carbonate. Also multivalent ions can also be injected with the inhibitor if pH of the injection solution is low. As pH rises due to dilution or neutralization, precipitation will result.
A combination chelation/precipitation method has been proposed. The inhibitor remains soluble during injection due to chelation of added multivalent ions by an added chelant. Upon setting in the reservoir, the equilibrium shifts toward the calcium/inhibitor pair, resulting in precipitation.
One method has been proposed that does not require added ions. A low solubility inhibitor is made soluble by raising the pH of the injecting solution. On dilution and neutralizing, the chemical will fall out of solution.
Other methods of inhibitor placement have been mentioned. One involves a water-dispersible inhibitor injected in a water-in-oil emulsion, which reverts on water contact. It is proposed that organophosphonates can be retained more readily when injected with an adsorption agent (an amine or amine quaternary amxonium salt). Others have proposed that phosphonates adsorption last longer when used in various combinations with polymers. The polymer can be injected with the phosphonate or in alternate slugs.
The residual concentrations of phosphonates and phosphate esters can be easily and accurately determined in oil field brines by a titration method. However, no accurate method exists for field testing of polymer residuals.
Since precipitation squeezes are usually superior to adsorption squeezes, a superior squeeze chemical should be one whose calcium salt has a very low solubility. However, the solubility should not be so low that the concentration or produced inhibitor is below that required for effective scale inhibition.
Also, a inhibitor is needed that will inhibit barium sulfate scale as well as the more common scales. Barium sulfate scale is almost impossible to remove once formed and is becoming a more frequent problem, especially in Alaska and many foreign locations. In locations such as the North Sea, barium and strontium sulfate inhibition is becoming a major problem as waterflooding operations involving sea water increase.
Barium scales are a problem in waterflooding operations where sea water is used as an injection fluid. If the reservoir is high in barium, the sea water, being high in sulfate ion, will result in incompatible fluids (barium sulfate formation) in the reservoir. If the formation is high in calcium, calcium sulfate could result. Waterflooding (secondary recovery) or pressure augmentation--in order to increase production pressure--with other brines (not necessarily sea water) can result in incompatible fluids.
Scale inhibition studies have been carried out with calcium carbonate, calcium sulfate and barium sulfate. The precipitation of the inhibitor with calcium is unrelated to its intended inhibition. The inhibitor should also be capable of being precipitated with other metal ions such as magnesium, iron, chromium, etc.